EP3204798B1 - Recherche d'une fraction d'hydrocarbures combinée et de la porosité par spectroscopie diélectrique - Google Patents

Recherche d'une fraction d'hydrocarbures combinée et de la porosité par spectroscopie diélectrique Download PDF

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Publication number
EP3204798B1
EP3204798B1 EP14859306.4A EP14859306A EP3204798B1 EP 3204798 B1 EP3204798 B1 EP 3204798B1 EP 14859306 A EP14859306 A EP 14859306A EP 3204798 B1 EP3204798 B1 EP 3204798B1
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Prior art keywords
water
porous medium
earth formation
dielectric
polarization
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German (de)
English (en)
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EP3204798A1 (fr
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Vitaly Nikolaevich Dorovsky
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Baker Hughes Holdings LLC
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Baker Hughes Holdings LLC
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    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01N—INVESTIGATING OR ANALYSING MATERIALS BY DETERMINING THEIR CHEMICAL OR PHYSICAL PROPERTIES
    • G01N27/00—Investigating or analysing materials by the use of electric, electrochemical, or magnetic means
    • G01N27/02—Investigating or analysing materials by the use of electric, electrochemical, or magnetic means by investigating impedance
    • G01N27/026—Dielectric impedance spectroscopy
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/26—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device
    • G01V3/28—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with magnetic or electric fields produced or modified either by the surrounding earth formation or by the detecting device using induction coils
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/18—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging
    • G01V3/30—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation specially adapted for well-logging operating with electromagnetic waves
    • G—PHYSICS
    • G01—MEASURING; TESTING
    • G01V—GEOPHYSICS; GRAVITATIONAL MEASUREMENTS; DETECTING MASSES OR OBJECTS; TAGS
    • G01V3/00—Electric or magnetic prospecting or detecting; Measuring magnetic field characteristics of the earth, e.g. declination, deviation
    • G01V3/38—Processing data, e.g. for analysis, for interpretation, for correction
    • Y—GENERAL TAGGING OF NEW TECHNOLOGICAL DEVELOPMENTS; GENERAL TAGGING OF CROSS-SECTIONAL TECHNOLOGIES SPANNING OVER SEVERAL SECTIONS OF THE IPC; TECHNICAL SUBJECTS COVERED BY FORMER USPC CROSS-REFERENCE ART COLLECTIONS [XRACs] AND DIGESTS
    • Y02—TECHNOLOGIES OR APPLICATIONS FOR MITIGATION OR ADAPTATION AGAINST CLIMATE CHANGE
    • Y02A—TECHNOLOGIES FOR ADAPTATION TO CLIMATE CHANGE
    • Y02A90/00—Technologies having an indirect contribution to adaptation to climate change
    • Y02A90/30—Assessment of water resources

Definitions

  • This disclosure generally relates to exploration and production of hydrocarbons involving investigations of regions of an earth formation penetrated by a borehole. More specifically, the disclosure relates to the dielectric spectroscopy of an earth formation using a logging tool in a borehole.
  • Electrodes - current source(s) or sink(s) - are used in conjunction with a return electrode (which may be a diffuse electrode such as a logging tool's body or mandrel).
  • a measurement current flows in a circuit that connects a current source to the measurement electrode(s), through the earth formation to the return electrode, and back to the current source in the tool.
  • an antenna within the measuring instrument induces a current flow within the earth formation.
  • WO2013/012349 determines the bulk fractions of water and oil using a spectral image of permittivity based on an estimated rate of change at a high frequency of imaginary part vs. real part following the H192iak-Negami relaxation curve.
  • the present disclosure is directed to a method according to claim 1 and to an apparatus according to claim 13.
  • One embodiment according to the present disclosure includes a method of evaluating an earth formation including a porous medium.
  • the method includes making a plurality of estimates of complex permittivity ( ⁇ ) based on measurements using an electromagnetic tool at a plurality of frequencies in a borehole penetrating the earth formation while the porous medium of the formation is saturated with a mixture of water and a plurality of hydrocarbon phases including oil and gas; and estimating a parameter of interest of the earth formation using the plurality of estimates by using a spectral dielectric curve constant (v) for the porous medium, the spectral dielectric curve constant (v) invariant with respect to a ratio of water to hydrocarbons in the porous medium and determined by an estimated rate of change between estimates of the plurality of estimates of complex permittivity of an imaginary part relative to a real part of each estimate.
  • ⁇ complex permittivity
  • the method further includes generating a spectral dielectric curve by mapping the real part with respect to the imaginary part for each estimate of the plurality of estimates.
  • the method includes using a model correlating the plurality of estimates to a HVeronicaiak-Negami relaxation curve to determine a value for at least one polarization parameter associated with the curve.
  • the at least one polarization parameter may comprise ⁇ , wherein ⁇ relates to a degree of saturation of the porous medium with the plurality of hydrocarbon phases in the presence of water.
  • the method may include using the spectral dielectric curve constant (v) and the value for ⁇ to determine a value for another polarization parameter ⁇ , wherein ⁇ relates to a degree of saturation of the porous medium with water, and wherein ⁇ relates to a polarization angle.
  • the method may include determining values ⁇ 0 and ⁇ for ⁇ using a relationship defining ⁇ as a function of ⁇ , wherein ⁇ 0 corresponds to the value for ⁇ ( ⁇ 0 ) and ⁇ corresponds to a second value for beta correlated with a state of the porous medium free from the plurality of hydrocarbon phases.
  • the at least one property includes at least one of: i) combined hydrocarbon fraction, ii) the bulk fraction of water, and iii) porosity.
  • the method may include using the values ⁇ 0 and ⁇ to estimate a bulk water fraction of the porous medium or a bulk hydrocarbon fraction of the porous medium.
  • the method may include determining a value ⁇ for ⁇ using a relationship defining ⁇ as a function of ⁇ , wherein ⁇ corresponds to a second value for beta correlated with a state of the porous medium free from the plurality of hydrocarbon phases; and using the value ⁇ to estimate a porosity of the porous medium.
  • the method may also include conveying the electromagnetic tool in the borehole.
  • the electromagnetic tool may use electrical induction.
  • the method may also include using the electromagnetic tool for making the measurements at the plurality of frequencies.
  • One embodiment according to the present disclosure includes an apparatus for evaluating an earth formation.
  • the apparatus includes a carrier configured to be conveyed in a borehole penetrating the earth formation; an electromagnetic tool disposed on the carrier and configured to make measurements indicative of an imaginary part and a real part of a permittivity of the earth formation at a plurality of frequencies; and at least one processor.
  • the at least one processor is configured to perform the method as described above.
  • Induction logging tools may operate by inducing a current flow within an earth formation and detecting the magnitude of the induced current, which is responsive to properties of the earth formation.
  • properties of an earth formation may be estimated using information acquired in induction logging.
  • dielectric spectroscopy and specifically the estimation of electric permittivity of a saturated medium of an earth formation, is used to determine properties of the formation.
  • An estimate of electric permittivity includes an imaginary part and a real part. It is known that each of the imaginary part and the real part of an estimate may vary in dependence upon the frequency of the electrical signal used in making the estimate. By making several estimates over a range of frequencies and characterizing the relationship of changes in both the real and imaginary parts of the estimates with frequency, information may be obtained about the state of the earth formation (e.g., porosity).
  • a parameter of interest of the earth formation is estimated for earth formations including a porous medium saturated with a mixture of water and a plurality of hydrocarbon phases (e.g., oil and natural gas).
  • a parameter of interest of the earth formation including a porous medium saturated with a mixture of water and a plurality of hydrocarbon phases (e.g., oil and natural gas).
  • hydrocarbon phases e.g., oil and natural gas.
  • the parameter of interest is estimated using a plurality of estimates of complex permittivity at a plurality of frequencies.
  • the parameter of interest is estimated by using a spectral dielectric curve constant (v) for the porous medium.
  • the spectral dielectric curve constant (v) is invariant with respect to a ratio of water to hydrocarbons in the porous medium and determined by an estimated rate of change between estimates of the plurality of estimates of complex permittivity of an imaginary part relative to a real part of each estimate.
  • electric permittivity may be estimated using an electromagnetic tool configured to generate an electric current at a plurality of frequencies.
  • the electromagnetic tool may include an inductive electromagnetic probe that may be electrically coupled to an earth formation from inside of a borehole penetrating the earth formation.
  • Dielectric permittivity may be obtained by solving Maxwell's equations.
  • M z is the receiver coil magnetic moment
  • k is a wave number
  • ⁇ is a circular frequency
  • R is a radial distance
  • r and z are coordinates in the cylindrical coordinate system
  • ⁇ is the permeability of the material
  • ⁇ ' and ⁇ " are real and imaginary parts of dielectric permittivity.
  • the dielectric permittivity may be estimated using methods known to those of skill in the art, including, but not limited to one or more of: (i) a Newton method and (ii) a Marquardt-Levenberg method.
  • the estimated imaginary and real parts of permittivity of the earth formation are then used to estimate at least one parameter of interest of the earth formation.
  • the at least one parameter of interest includes, but is not limited to: (i) percentage of mixed hydrocarbons; (ii) percentage of water; or (iii) formation porosity.
  • a dipole antenna configured to emit electromagnetic waves is placed in the center of the borehole with a receiver antenna located in the borehole at a certain distance from the transmitter, then real and imaginary parts of the magnetic field may be measured by the receiver antenna.
  • a spectral image of dielectric permittivity may be generated using the imaginary and real parts of permittivity over a plurality of frequencies.
  • the spectral image may also be referred to as a "spectral dielectric curve" and a "polarization curve”. Each point on the spectral image of dielectric permittivity may correspond to a specific frequency in the electromagnetic spectrum.
  • aspects of the disclosure may include generating a spectral dielectric curve by mapping the real part with respect to the imaginary part for each estimate of the plurality of estimates.
  • the bulk fractions of water and the hydrocarbon mixture in the earth formation may then be estimated using the spectral dielectric curve (spectral image) of dielectric permittivity.
  • aspects of the present disclosure include using a borehole inductive electromagnetic tool to measure the real and imaginary parts of the dielectric spectrum at a fixed borehole depth. This may include estimating all spectral characteristics of the H192iak-Negami curve. The percentage of plurality of hydrocarbon phases contained in the formation pores may be estimated from hydrocarbon and / or water saturation characteristics using methods disclosed herein. Using the tabulated curves for sandstones, carbonates, etc. and the limit value of another polarization parameter, further aspects of the disclosure may enable estimation of the formation porosity. Example apparatus and method embodiments for estimating properties of the formation are discussed below.
  • FIG. 1 shows an electromagnetic tool 10 suspended, in a borehole 12 penetrating earth formation 13, from a suitable cable 14 that passes over a sheave 16 mounted on drilling rig 18.
  • the cable 14 includes a stress member and seven conductors for transmitting commands to the tool and for receiving data back from the tool as well as power for the tool.
  • the electromagnetic tool 10 is raised and lowered by draw works 20.
  • Electronic module 22, on the surface 23, transmits the required operating commands downhole and in return, receives data back which may be recorded on an archival storage medium of any desired type for concurrent or later processing.
  • the data may be transmitted in analog or digital form.
  • Data processors such as a suitable computer 24, may be provided for performing data analysis in the field in real time or the recorded data may be sent to a processing center or both for post processing of the data. Some or all of the processing may also be done by using a downhole processor at a suitable location on the logging tool 10. While a wireline conveyance system has been shown, it should be understood that embodiments of the present disclosure may be utilized in connection with tools conveyed via rigid carriers (e.g., jointed tubular or coiled tubing) as well as non-rigid carriers (e.g., wireline, slickline, e-line, etc.). Some embodiments of the present disclosure may be deployed along with LWD/MWD tools.
  • rigid carriers e.g., jointed tubular or coiled tubing
  • non-rigid carriers e.g., wireline, slickline, e-line, etc.
  • the electromagnetic tool 10 may include at least one transmitting antenna and at least two receiving loop antennas mounted on a pad.
  • the tool may be operated in at least two modes.
  • a first mode may be referred to as Mini-MPR (Multiple propagation resistivity) mode that may measure attenuation and a phase difference between the two receivers.
  • the electromagnetic tool 10 may also be operated in a second mode (an induction mode) in which a compensated magnetic field (voltage) may be measured.
  • the current in the transmitter coil may induce a magnetic field in the earth formation 13. This magnetic field, in turn, may cause eddy currents to flow in the earth formation 13. Because of the presence of these formation currents, a magnetic field may be coupled into a receiver coil R thereby generating a receiver signal.
  • Logging tools having "a receiver coil” and "a transmitter coil” each comprised of several coils arranged in a predetermined fashion to obtain a desired response may be used.
  • the receiver signal may then be amplified and applied to one or more phase sensitive detectors (PSDs).
  • PSDs phase sensitive detectors
  • Each PSD may detect a phase component signal having a phase identical to a phase reference signal which may also be applied to the detector.
  • the phase reference signal may have a predetermined phase relationship to the current in the transmitter coil(s).
  • the output of the PSD(s) may be further processed downhole, or may be sent uphole to surface equipment for processing or display to an operating engineer.
  • one receiver loop coil may serve as a main receiver and the other as a bucking receiver.
  • the transmitting antennas may include loops and/or electric dipoles.
  • the transmitters and receivers may be in one of three orientations. If the z-axis of the tool is parallel to the longitudinal axis of the tool, then the x-axis may be radial through the center of the pad, and the y-axis may be tangential to the pad.
  • the zz-component may refer to a z-source and a z-receiver and so on. In some embodiments, xx-transmitters and receivers may be used.
  • FIG. 2A shows an electromagnetic tool 10 for one embodiment according to the present disclosure.
  • the electromagnetic tool 10 may include a body 55 with two pads 51A, 51B extended on extension devices 53A, 53B. Two pads are shown for illustrative purposes and, in actual practice, there may be more pads.
  • the extension devices 53A, 53B may be electrically operated, electromechanically operated, mechanically operated or hydraulically operated. With the extension devices 53A, 53B fully extended, the pads 51A, 51B can make contact with the borehole wall (not shown) and make measurements indicative of properties of the borehole wall.
  • Orientation sensors (not shown) may provide an indication of the orientation of the electromagnetic tool 10.
  • cable depth measurements may be obtained using a sensor (not shown) at the surface that measures the amount of cable spooled out.
  • accelerometers may be used downhole to provide other measurements indicative of the depth of the electromagnetic tool 10.
  • the orientation sensors may include accelerometers, magnetometers or gyroscopes. Depth may also be estimated from a gy
  • FIG. 2B An exemplary arrangement of dual transmitters and receivers on each of the pads is shown in FIG. 2B . Shown therein is pad 51A with two transmitters 55A, 55B disposed about two receivers 57A, 57B. Also depicted schematically by arrows in FIG. 2B are measurements that may be made by each of the two receivers 57A, 57B corresponding to signals generated by each of the two transmitters 55A, 55B.
  • the use of dual transmitters may provide a symmetrical response.
  • the use of dual transmitters may also reduce effects of borehole rugosity.
  • the use of dual transmitters may reduce electronics-related errors in attenuation measurement. The electronics-related errors may not affect the phase difference measurement.
  • the ratio of the two receiver outputs R T 1 for the 1st transmitter may be derived from the ratio:
  • R T 1 G 2 H 2
  • G 1 H 1 G 2 G 1 A 2 A 1 e i ⁇
  • a 1 and A 2 are the amplitudes of H 1 and H 2 , respectively;
  • the gain change affects attenuation measurement but not the phase difference measurement.
  • Averaging equations (3) and (4) may remove the effect of gain variation.
  • FIG. 3A shows a schematic of a generic tool configuration for one embodiment according to the present disclosure.
  • Pad 51A may include two receiver arrays 103A, 103B.
  • the coils 101A, 101B of the upper and lower receiver arrays may be aligned radially with respect to the tool axis (movement) direction.
  • the receiver coils 105 are separated laterally by a constant distance that is determined by the azimuthal resolution of the electromagnetic tool.
  • Two transmitting antennas 101A, 101B may be placed above receiver array 103A and below receiver array 103B.
  • the transmitting antennas 101A, 101B may be operated one at a time during which measurements from each and every receiver pair are made.
  • An exemplary current flow direction for the transmitters 101A, 101B is shown by the arrows in FIG. 3A . With the indicated current flow of the transmitters 101A, 101B and the coil orientation of the receivers 105, the measurements made would be xx-measurements.
  • the measurements may include attenuation rate, phase difference, or compensated magnetic field.
  • FIG. 3B shows a schematic of another embodiment of a generic tool configuration with staggered receiver pairs according to the present disclosure.
  • the receiver pairs may be staggered in the tool axis direction, allowing a small separation between the receiver pairs.
  • the upper receiver array 103A' may comprise two staggered rows of receivers 105 and the lower receiver array 103B' may comprise two staggered rows of receivers 105 to reduce the gaps in azimuthal coverage of the configuration of FIG. 3A .
  • FIG. 4A is a schematic of a transmitter for one embodiment according to the present disclosure.
  • Transmitters 101A' and 101B' may have wires wound around the pad 51A.
  • the wire paths may be substantially normal to the tool axis, going in the front, back, and on sides of the pad 51A. With the configuration shown in FIG. 4A , the measurements would be zx-measurements.
  • FIG. 4B is a schematic of a transmitter for another embodiment according to the present disclosure.
  • Transmitters 101A", 101B" may be electric dipoles normal to the tool axis.
  • FIG. 5 is a flow chart of one method 500 for estimating a fluid saturation according to one embodiment of the present disclosure.
  • electromagnetic tool 51A may be conveyed in the borehole 12.
  • signals at a plurality of frequencies may be transmitted from transmitters 101A, 101B into the earth formation. In some embodiments, at least one of the plurality of frequencies may be at a frequency at or above 500 MHz.
  • receivers 103A, 103B may generate an output indicative the complex dielectric permittivity of the earth formation 13.
  • a rate of change of the imaginary part of the complex dielectric permittivity relative to the real part of the complex dielectric permittivity may be estimated using the generated output.
  • a parameter of interest may be estimated using the estimated rate of change.
  • the selection of the plurality of frequencies may include frequencies at or near the high frequency limit of the real part of dielectric permittivity for the particular polarization type of the earth formation.
  • Several basic polarization types depending on colloid structure of oil, water contact with the containing porous medium, and water-oil contact in the containing medium can be identified. The physical bases in these cases correspond to migration polarization (the Maxwell-Wagner polarization) at the contacts between colloid particles in oil, polarization of the double layer and bulk charge at the contacts between water and the rock matrix of the containing porous medium, etc.
  • Each polarization type may be identified with a specific structural unit of the medium and cataloged in the dielectric spectra. Determination of the particle type in the colloid solution in the porous medium may be then reduced to the problem of identification of the cataloged and the measured spectra. It should be noted that polarization types may be reduced to the following three basic polarization types.
  • FIG. 6 shows a set of complex permittivity curves depicting spectral images of dielectric permittivity for different relaxations related to polarization types and associated with colloidal structure of fluid within a saturated porous medium.
  • the Maxwell-Wagner relaxation determines the phase of colloid particles
  • the m-th power law relaxation corresponds to laminated or disk-shaped micellar colloid particles
  • the Debye relaxation corresponds to crystalline solid colloid particles
  • the Cole-Davidson relaxation corresponds to local crystalline structuring in colloid particles, etc.
  • the structure of water-hydrocarbon mixture and colloid oil contents in the saturated porous medium may be identified.
  • the structure of the water-oil mixture may be indicative of permeability of the earth formation.
  • water-saturated sandstones and dolomites may have a polarization type that demonstrates Cole-Cole relaxation.
  • the polarization type may be identified using electromagnetic logging of the borehole.
  • fresh water-saturated porous media may be characterized by high dielectric permittivity (up to 10 3 -10 4 ) at characteristic relaxation frequencies.
  • FIG. 7 shows a chart with a set of curves representing the frequency dependence complex dielectric permittivity of sandstone saturated with (i) water and (ii) a mixture of water and transformer oil.
  • Curve 710 indicates the real part of dielectric permittivity for sandstone saturated with water.
  • Curve 720 indicates the imaginary part of dielectric permittivity for sandstone saturated with water.
  • Curve 730 indicates the real part of dielectric permittivity for sandstone saturated with a mixture of water and transformer oil.
  • Curve 740 indicates the imaginary part of dielectric permittivity for sandstone saturated with a mixture of water and transformer oil.
  • step 750 may include finding a bulk fraction of water if there are no mixed phase hydrocarbons and a bulk fraction of water in the presence of mixed phase hydrocarbons. The difference between these two values may yield the bulk fraction of mixed phase hydrocarbons.
  • the method of finding water saturation and hydrocarbon saturation is illustrated below using the cases of the Cole-Cole relaxation and the HVeronicaiak-Negami relaxation.
  • the estimate of the dielectric permittivity may assume a natural porous medium, such as sandstone or dolomite, that is saturated with water and assuming that the dielectric polarization type of this system was established via borehole measurements.
  • each of the imaginary part and the real part of an estimate of complex permittivity may vary in dependence upon the frequency of the electrical signal used in making the estimate.
  • parameters of interest of the earth formation After making several estimates over a range of frequencies, it is possible to estimate parameters of interest of the earth formation by characterizing the relationship of changes in both the real and imaginary parts of the estimates with frequency. Parameters of interest are estimated using techniques related to a rate of change of between estimates of a plurality of estimates of complex permittivity of an imaginary part relative to a real part of each estimate. Method embodiments may include generating a spectral dielectric curve by mapping the real part with respect to the imaginary part for each estimate of the plurality of estimates.
  • FIG. 8 shows an exemplary set of curves for sandstone expressing complex dielectric permittivity over a range of frequencies.
  • the Cole-Cole relaxation is typically observed as shown in as curve 810.
  • ⁇ complex dielectric permittivity
  • ⁇ ⁇ the asymptotic value of the real part of this polarization type at high frequencies
  • ⁇ s is the static value of dielectric permittivity
  • ⁇ relaxation time
  • ⁇ is a parameter ranging from 0 to 1, which characterizes the polarization angle.
  • Novel aspects of the present disclosure further include the determination that curve 820 may also represent the Hoviciak-Negami relaxation observed when mixed phase hydrocarbons are present, due to the similarities in the dielectric constant between mixed phase hydrocarbons (particularly oil and gas) and oil alone.
  • curve 820 may also represent the Hoviciak-Negami relaxation observed when mixed phase hydrocarbons are present, due to the similarities in the dielectric constant between mixed phase hydrocarbons (particularly oil and gas) and oil alone.
  • curve 820 may also represent the Hoviciak-Negami relaxation observed when mixed phase hydrocarbons are present, due to the similarities in the dielectric constant between mixed phase hydrocarbons (particularly oil and gas) and oil alone.
  • curve 820 may also represent the Hucun-Negami relaxation observed when mixed phase hydrocarbons are present, due to the similarities in the dielectric constant between mixed phase hydrocarbons (particularly oil and gas) and oil alone.
  • ⁇ max " ⁇ s ⁇ ⁇ ⁇ ⁇ tan 1 ⁇ ⁇ ⁇ / 4 / 2
  • ⁇ max " is the maximal loss factor
  • ⁇ s is the static value of the real part of dielectric
  • ⁇ ⁇ is its high-frequency limit
  • ⁇ is the polarization parameter
  • ⁇ ⁇ ( K ) is a given universal function of water saturation (water fraction in per cent).
  • the universal curve ⁇ ⁇ ( K% ) may be obtained via laboratory experiments, and ⁇ max " , ⁇ max ′ , ⁇ may be obtained via inductive logging.
  • the polarization curve may be estimated as the H192iak-Negami formula as shown as curve 820 in FIG. 8 and expressed as follows.
  • ⁇ * ⁇ ⁇ + ⁇ s ⁇ ⁇ ⁇ 1 + i ⁇ 1 ⁇ ⁇ ⁇ where there are two polarization parameters: ⁇ and ⁇ .
  • ⁇ ⁇ ⁇ ⁇ , 0 + ⁇ s ⁇ ⁇ 1 / 2 + ...
  • the quadratic terms are to be taken into account.
  • water saturation may be calculated for the no-oil case K waler using the right hand angle.
  • Polarization parameters ⁇ max " and ⁇ max ′ may be found via the right hand angle.
  • the Debye polarization (a special case of the Cole-Cole polarization with a single relaxation time of the corresponding distribution function) characterizes polarization in the system of independent oscillators in the external electric field. Asymmetry of the Debye polarization curve is related to the Cole-Davidson polarization curve. The physics behind this deformation of the polarization curve may be emerging non-linear interaction in the system of independent oscillators (polarizing dipoles in the external electric field). The analysis of the experimental spectral data for dielectric permittivity of the porous media saturated with water-oil mixture and for water-oil emulsions appears to indicate that, in the porous media, oil takes the form of droplets in water, i.e. a system similar to that of water-oil emulsions in the porous media.
  • ⁇ is relaxation time
  • ⁇ is the frequency of electromagnetic excitation of the medium
  • a and b are parameters characterizing the porous medium (0 ⁇ a ⁇ 1; 1 ⁇ b > 0).
  • v is a spectral dielectric curve constant that characterizes a reservoir saturated with water.
  • the hydrocarbon saturation variable ⁇ varies from 1 to ⁇ ⁇ .
  • the current value of ⁇ , ⁇ 0 corresponds to the current value of ⁇ , ⁇ 0 , found for any v, as calculated above.
  • the parameter ⁇ may vary from 0 to ⁇ ⁇ , as is apparent from the graph.
  • ⁇ * 1 ⁇ 4 ⁇ arctg ⁇ ⁇ * .
  • K ⁇ ⁇ * ⁇ 100 %
  • K water % ⁇ ⁇ * ⁇ 100 %
  • K h 1 ⁇ ⁇ ⁇ * ⁇ 100 %
  • ⁇ ⁇ ⁇ .
  • K p ⁇ ⁇ ⁇ 100%.
  • Any current value of ⁇ may help compare water fraction (percent) in a water- and mixed phase hydrocarbon-saturated porous reservoir using equations (25), and porosity may be determined from the tabulated curve.
  • FIG. 10 is a flow chart of one method 1000 for estimating changes in water fraction in the water-hydrocarbon reservoir and its porosity according to one embodiment of the present disclosure.
  • electromagnetic tool 51A may be conveyed in the borehole 12.
  • signals at a plurality of frequencies may be transmitted from transmitters 101A, 101B into the earth formation. In some embodiments, at least one of the plurality of frequencies may be at a frequency at or above 500 MHz.
  • receivers 103A, 103B may generate an output indicative the complex dielectric permittivity of the earth formation 13.
  • mixed hydrocarbon saturation parameter ( ⁇ 0 ) and spectral dielectric curve constant (v) may be estimated using the generated output.
  • the method in accordance with the presently disclosed embodiment of the disclosure involves several computational steps. As would be apparent by persons of ordinary skill, these steps may be performed by computational means such as a computer, or may be performed by a combination of computational means and an analyst performing some steps manually.
  • Implicit in the processing of the acquired data is the use of a computer program implemented on a suitable computational platform (dedicated or general purpose) and embodied in a suitable machine readable medium that enables the processor to perform the control and processing.
  • processor as used in the present disclosure is intended to encompass such devices as microcontrollers, microprocessors, field-programmable gate arrays (FPGAs) and the storage medium may include ROM, RAM, EPROM, EAROM, solid-state disk, optical media, magnetic media and other media and/or storage mechanisms as may be deemed appropriate.
  • processing and control functions may be performed downhole, at the surface, or in both locations.

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  • Investigating Or Analyzing Materials By The Use Of Electric Means (AREA)

Claims (13)

  1. Procédé mis en œuvre par un ordinateur pour évaluer une formation terrestre incluant un milieu poreux, le procédé comprenant :
    la réalisation d'une pluralité d'estimations de permittivité complexe en fonction de mesures à l'aide d'un outil électromagnétique à une pluralité de fréquences dans un trou de forage pénétrant dans la formation terrestre pendant que le milieu poreux de la formation est saturé avec un mélange d'eau et d'une pluralité de phases hydrocarbonées incluant de l'huile et du gaz ; et
    l'estimation d'une pluralité de paramètres de polarisation à l'aide d'une partie réelle et d'une partie imaginaire de chaque estimation de permittivité complexe de la formation terrestre,
    dans lequel un premier paramètre de polarisation de la pluralité est au moins l'un d'un paramètre de saturation d'hydrocarbures et d'un paramètre de saturation d'eau pour un point de saturation complet (β* α*),
    dans lequel l'utilisation de la partie réelle et de la partie imaginaire comprend la modélisation de la permittivité en guise d'une courbe de Havriliak-Negami, l'estimation d'une pluralité de caractéristiques spectrales de la courbe de Havriliak-Negami, et l'utilisation d'une constante de courbe diélectrique spectrale v = 2 ε " max / ε 0 − ε ∞
    Figure imgb0037
    pour le milieu poreux, la constante de courbe diélectrique spectrale (v) ne variant pas par rapport à un ratio de l'eau aux hydrocarbures dans le milieu poreux, dans lequel ε"max est le facteur de perte maximum, ε0 est la valeur statique de la partie réelle de la permittivité diélectrique et ε∞ est la limite haute fréquence de la partie réelle de la permittivité diélectrique ; et
    l'estimation d'au moins une propriété de la formation terrestre à l'aide des premiers paramètres de polarisation, dans lequel l'au moins une propriété comprend au moins l'un de : (i) la porosité (ii) la masse hydrocarbonée combinée ; et (iii) la fraction massique d'eau.
  2. Procédé selon la revendication 1, dans lequel le premier paramètre de polarisation comprend β, dans lequel β se rapporte à un degré de saturation du milieu poreux avec la pluralité de phases hydrocarbonées en présence d'eau.
  3. Procédé selon la revendication 2, comprenant la détermination de la valeur pour β à l'aide d'un angle d'intersection (ϕ) de deux courbes Im ε = Φ(Re ε) et Im ε = 0 au point où ε = ε0 et un second angle d'intersection (ψ) des deux courbes Im ε = Φ(Re ε) et Im ε = 0 au point où ε = ε∞.
  4. Procédé selon la revendication 2, comprenant l'utilisation de la constante de courbe diélectrique spectrale (v) et de la valeur pour β pour déterminer une valeur pour un autre paramètre de polarisation α, dans lequel α se rapporte à un degré de saturation du milieu poreux avec de l'eau, et dans lequel α se rapporte à un angle de polarisation.
  5. Procédé selon la revendication 4, comprenant la détermination de valeurs α0 et α* pour a à l'aide d'une relation définissant α en tant que fonction de β, dans lequel α0 correspond à la valeur pour β (β0) et α* correspond à une seconde valeur pour bêta corrélée avec un état du milieu poreux exempt de la pluralité de phases hydrocarbonées.
  6. Procédé selon la revendication 5, comprenant l'utilisation des valeurs α0 et α* pour estimer une fraction d'eau massique du milieu poreux.
  7. Procédé selon la revendication 5, comprenant l'utilisation des valeurs α0 et α* pour estimer une fraction d'hydrocarbures massique du milieu poreux.
  8. Procédé selon la revendication 4, comprenant :
    la détermination d'une valeur α* pour a à l'aide d'une relation définissant α en tant que fonction de β, dans lequel α* correspond à une seconde valeur pour bêta corrélée avec un avec un état du milieu poreux exempt de la pluralité de phases hydrocarbonées ; et
    l'utilisation de la valeur α* pour estimer une porosité du milieu poreux.
  9. Procédé selon la revendication 1, comprenant en outre l'utilisation de l'outil électromagnétique pour la réalisation des mesures à la pluralité de fréquences.
  10. Procédé selon la revendication 1, dans lequel l'outil électromagnétique utilise une induction électrique.
  11. Procédé selon la revendication 1, comprenant en outre l'exécution d'au moins l'un de :
    i) un enregistrement du paramètre d'intérêt ;
    ii) un affichage du paramètre d'intérêt ;
    iii) une modification d'une opération de perçage dans la formation terrestre ;
    iv) une modification d'une opération de récupération dans la formation terrestre.
  12. Procédé selon la revendication 1, comprenant en outre :
    le transport de l'outil électromagnétique dans le trou de forage.
  13. Appareil pour évaluer une formation terrestre incluant un milieu poreux, l'appareil comprenant :
    un support configuré pour être transporté dans un trou de forage pénétrant dans la formation terrestre ;
    un outil électromagnétique disposé sur le support et configuré pour réaliser des mesures indiquant une partie imaginaire et une partie réelle d'une permittivité complexe de la formation terrestre à une pluralité de fréquences ; et
    au moins un processeur configuré pour :
    réaliser les mesures avec l'outil électromagnétique dans un trou de forage pénétrant dans la formation terrestre ;
    réaliser une pluralité d'estimations de permittivité complexe en fonction des mesures ; et
    estimer une pluralité de paramètres de polarisation à l'aide de la partie réelle et de la partie imaginaire de chaque estimation de permittivité complexe de la formation terrestre,
    dans lequel un premier paramètre de polarisation de la pluralité est au moins l'un d'un paramètre de saturation d'hydrocarbures et d'un paramètre de saturation d'eau pour un point de saturation complet (β*, α*),
    dans lequel l'utilisation de la partie réelle et de la partie imaginaire comprend la modélisation de la permittivité en guise d'une courbe de Havriliak-Negami, l'estimation d'une pluralité de caractéristiques spectrales de la courbe de Havriliak-Negami, et l'utilisation d'une constante de courbe diélectrique spectrale v = 2 ε " max / ε 0 − ε ∞
    Figure imgb0038
    pour le milieu poreux, la constante de courbe diélectrique spectrale (v) ne variant pas par rapport à un ratio de l'eau aux hydrocarbures dans le milieu poreux, dans lequel ε"max est le facteur de perte maximum, ε0 est la valeur statique de la partie réelle de la permittivité diélectrique et ε∞ est la limite haute fréquence de la partie réelle de la permittivité diélectrique ; et
    estimer au moins une propriété de la formation terrestre à l'aide des premiers paramètres de polarisation, dans lequel l'au moins une propriété comprend au moins l'un de (i) la porosité (ii) la masse hydrocarbonée combinée ; et (iii) la fraction massique d'eau.
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US11788402B2 (en) * 2019-07-08 2023-10-17 Schlumberger Technology Corporation Methods for determining a volume fraction of water and water salinity in organic shale reservoirs using multi-frequency dielectric well logging measurements

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US8977500B2 (en) * 2010-04-13 2015-03-10 Baker Hughes Incorporated Dielectric spectroscopy for downhole fluid analysis during formation testing
US20140025357A1 (en) * 2011-02-02 2014-01-23 Statoil Petroleum As Method of predicting the response of an induction logging tool
CA2833719C (fr) * 2011-04-18 2016-10-18 Halliburton Energy Services, Inc. Procedes et systemes pour estimer une resistivite et une porosite de formation
US10145975B2 (en) * 2011-04-20 2018-12-04 Saudi Arabian Oil Company Computer processing of borehole to surface electromagnetic transmitter survey data
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US9791588B2 (en) * 2013-07-10 2017-10-17 Baker Hughes Incorporated Finding porosity and oil fraction by means of dielectric spectroscopy
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